The present invention relates generally to data discrimination in applications such as, for example, seismic imaging and more particularly to a method for separating a particular sub-set of seismic data from an overall set of seismic data by utilizing a gather sensitive data discrimination approach in order to evaluate a particular subsurface seismic region.
In fields such as geophysics and geology, knowledge of the subsurface structure of the ground is useful, for example, in the selection of potential well sites and in fault studies. In the past, a number of different methods have been implemented with the goal of rendering images which impart such knowledge of the subsurface geologic structure. As will be seen, the accuracy of results obtained using these methods is dependent upon specific processing techniques for separating/enhancing seismic data of a selected type from an overall set of seismic data. One exemplary method, which benefits from the advantages of the present invention, is commonly referred to as crosswell imaging (also known as transmission tomography) and will be described immediately hereinafter.
Turning immediately to FIG. 1, crosswell imaging is typically performed using a crosswell imaging system which is generally indicated by the reference numeral 10. In system 10, seismic energy 12 is transmitted through a subsurface region 14 of the ground using a source 16 which is positioned in a first borehole 18. In state of the art systems, source 16 typically transmits seismic energy 12 into region 14 in the form of a swept frequency signal (chirp) which covers a predetermined frequency range resulting in transmitted energy in the form of compressional (p) and shear (s) waves. Source 16 is selectively movable between a series of positions S.sub.1 through S.sub.N using a winch and cable arrangement 20 wherein source 16 is shown initially at S.sub.1, adjacent the surface of region 14, and is shown in phantom at S.sub.N, adjacent the bottom of borehole 18. In order to properly couple source 16 with the subsurface surrounding first borehole 18, source 16 is typically immersed in a liquid or mud (neither of which is shown) which is either present or introduced into borehole 18. It should be noted that the subsurface structure of the ground being imaged is not illustrated in the present figure for purposes of clarity.
Still referring to FIG. 1, seismic energy 12 passes through region 14 and is received by a receiver array 22 which is positioned within a second borehole 24 at a distance w from the first borehole. Like source 16, receiver array 22 is normally immersed in some medium (not shown) for coupling the receiver to subterranean region 14 and, further, is selectively movable between positions R.sub.1 through R.sub.S using a winch and cable arrangement 26 wherein receiver array 22 is initially shown at R.sub.1, adjacent the surface of region 14 and is shown in phantom at R.sub.S, adjacent the bottom of borehole 24. It should be appreciated that the subterranean region of interest may comprise a zone (not shown for purposes of simplicity) which is at a known depth below the surface. In this case, the source and receiver array positions are adjusted accordingly such that the positions are spaced across the zone of interest rather than extending all the way to the surface. Receiver array 22 is made up of any suitable number of receivers such as, for example, five receivers 22a-e to record seismic energy 12 at five vertically spaced positions which are, of course, locationally dependent upon the overall position (one of R.sub.1 through R.sub.S) of the receiver array. It is noted that the first and second boreholes are illustrated as being perfectly vertically oriented for purposes of simplicity. Deviation of these boreholes from the perpendicular direction is typically referred to as well or borehole deviation. Inasmuch as borehole deviation is a concern, the reader is referred to the above referenced U.S. patent application which discloses a highly advantageous technique for use in borehole deviation correction.
During the operation of imaging system 10, a series of source scans is performed in each of which source 16 transmits seismic signal 12 in sequence from positions S.sub.1 through S.sub.N with receiver array 22 located at one of the positions selected from R.sub.1 through R.sub.S. In one method for completing the source scans, receiver array 22 is initially located at R.sub.1 during a first source scan. This first source scan begins with source 16 transmitting from S.sub.1 such that seismic signal 12 propagates through region 14 and is received at R.sub.1, as illustrated by raypaths 28a-e (partially shown) which are associated with each of receivers 22a-e. Raypaths are commonly used in the art as an expedient in describing the propagation of a wavefront through some medium wherein the raypath representation is perpendicular to the actual wavefront at any particular point therealong. For purposes of simplicity, raypaths 28 are shown as being straight. However, it is recognized that specific subsurface structural features such as, for example, stratifications, often result in raypaths which are not straight (i.e., directly from a source position to a receiver position) and that energy propagated along any of these raypaths is readily detected by receiver array 22. It is further recognized with regard to raypaths that seismic energy propagates along each raypath, as defined between source 16 and a respective receiver (one of 22a-e), at some average velocity which is dependent upon the structural features and velocity characteristics of the materials that are encountered along the overall length of the raypath. This average velocity is normally considered in terms of a "traveltime" which is associated with each raypath. Traveltimes are categorized in terms of particular characteristics of their associated seismic wave types. In the particular instance of seismic waves that travel from source to receiver without being reflected or converted to another wave type, traveltimes are referred to as direct arrival as contrasted with, for example, reflected (non-direct) arrival. One of skill in the art will recognize that a number of prior art techniques exist for separating direct arrival traveltime data, reflected arrival traveltime data and other known types of traveltime data from the overall seismic data record. However, it is submitted that each of these techniques is disadvantageous in certain respects, as will be described in further detail at appropriate points below.
Continuing to refer to FIG. 1 and as the scanning operation continues, source 16 is moved/scanned in the direction indicated by an arrow 27 to successive source positions up to and including S.sub.N such that data is recorded for each of positions S.sub.1 through S.sub.N with the receiver array located at R.sub.1. Next, receiver array 22 is moved in the direction indicated by an arrow 29 to position R.sub.2 (not shown) and source 16 is returned to position S.sub.1 at which time the source scan is repeated in the aforedescribed manner wherein seismic signal 12 is transmitted from each of positions S.sub.1 through S.sub.N so as to complete a second source scan corresponding to receiver position R.sub.2. The inception of the final source scan (performed with receiver array 22, shown in phantom, at Rs) is illustrated wherein source 16 initially transmits from S.sub.1 to R.sub.S. A final source scan is completed with the source/receiver positions Sn-Rn. It is noted that this operation may be performed in any number of different ways so long as measurements are obtained between each receiver position (within the overall receiver array) and each source position so as to produce a seismic data record which is representative of region 14.
The seismic data record, in and by itself, represents a relatively complex, rather large body of information which includes no less than six distinct categories of data (i.e., wave type arrivals) for a source which emits both p (compressional) and s (shear) waves. These wave types include direct arrival p (generally the first to be seen at the receiver); direct arrival s; reflected arrival p (hereinafter p--p); reflected arrival s (hereinafter s--s); p to s (hereinafter p-s) converted and reflected waves; and s to p (hereinafter s-p) converted and reflected. For purposes of brevity, many of these categories will not be described further. However, it is noted that all of these wave types and more are present in typical seismic data records even in the simplest of geologic settings, resulting in a seismic data record rich in overlapping (i.e., superimposed) arrival events. As will be seen immediately hereinafter, the prior art provides a limited number of effective techniques for separating these data types from the overall seismic data record.
Turning now to FIG. 2, one particular technique for graphically illustrating a portion of a seismic data record is referred to as a "gather" and is generally indicated by the reference numeral 40. A plurality 42 of horizontally extending seismic pressure wave traces or receiver channel traces are plotted in gather 40 in a manner which is well known in the art. The traces which make up gather 40 are selected from the overall seismic data record in a way which determines gather 40 as being one of a number of particular types. In the present example, gather 40 is known in the art as a common receiver gather. That is, all of the traces which make up the gather are measured from a single receiver position while the source position varies in depth. For example, source/receiver positions in a common receiver gather might include S.sub.1 /R.sub.1, S.sub.2 /R.sub.1 and S.sub.3 /R.sub.1, among many others. A vertically extending depth axis 44 indicates source depth which can readily be correlated with any of the traces. Gather 40 further includes a horizontally extending time axis 46 which indicates traveltimes along its length in milliseconds. As will be seen hereinafter, various techniques may be used in conjunction with gather 40 for use in the identification of specific types of arrival data whereby the identified data may be eliminated or included in a particular processing procedure.
Still referring to FIG. 2, one relatively straightforward technique relates to identification of direct arrival data (both p and s types). As described previously, p type direct arrival data is normally first to arrive at the receiver. Thus, an initial event parallel to a line 48 is made up of this type of data. Additionally, data which is generally parallel to the initial wave front is identifiable as p or s direct arrival. For example, events indicated at 50 and 52 are identified as such generally parallel events. At lines 58 and 60, s type direct arrivals are identifiable. In a manner which is similar to the direct arrival p type events, events such as those at lines 62 and 64, which are generally parallel with the s type direct arrivals (line 56), are identified.
Another, more complex, technique is particularly useful in identifying p--p reflection data through the process of elimination. This technique identifies data which cannot be p--p reflection data based upon a particular, known characteristic of the p--p reflection data which is present in common receiver gather 40. More specifically, it is known in the art that, for horizontal reflection horizons (i.e., structures or boundaries) which lie below a line (not shown) drawn between a particular source position and a particular receiver position, events/data within gather 40 associated with that horizon will have a positive slope. Therefore, it is recognized that events having a negative slope in gather 40 such as, for example, the event which lies along a line 66 cannot be p--p reflection data. With regard to this process of elimination technique as well as the previously described technique, it should be appreciated that a number of different common receiver gathers can be produced using one set of seismic imaging data. By way of example, for a typical seismic data record using two hundred different receiver positions, two hundred different common receiver gathers of varying usefulness can be generated. Each of these gathers may be subjected to the technique presently under discussion since each gather may contain different reflection events. Moreover, once this technique has been applied to all of the common receiver gathers, its results can be enhanced by applying it in a similar manner to another set or family of gathers which are known in the art as common source gathers (not shown). Each common source gather includes traces for a number of different receiver positions having one common source position. Thus, for a seismic data record taken using two hundred different source positions, two hundred common source gathers are separable from the overall record. The technique presently under discussion is equally applicable for use with such common source gathers. It is also mentioned that both the common source and common receiver gathers also contain valid reflection data events having a negative slope for reflection horizons (not shown) which lie above a line drawn between source/receiver pairs. With minor modification, the aforedescribed procedure may be used in this instance to eliminate as possible reflection data that data having a positive slope. One of skill in the art will recognize that a process of elimination technique such as this is most powerful in combination with other, positive identification processes in an overall procedure for identifying bona fide reflection data. One such process will be described immediately hereinafter.
Referring to FIGS. 1 and 2, another technique in the prior art identifies reflection data in a positive way as opposed to using the process of elimination. Basically, this technique relies on Snell's law in conjunction with the seismic velocity in an area immediately around either the source or receiver at the ends of a particular raypath depending upon the specific type of gather being used. In a simplified example which assumes a constant velocity along an exemplary ray path 70 (FIG. 1) which includes a single reflection at a horizontal surface 72, the angle of incidence .theta..sub.1 is equal to the angle of reflection .theta..sub.R. For the common receiver gather of FIG. 2, the slope of a p--p single/primary reflection event such as, for example, the event along a line 74 (hereinafter event 74) in the gather is controlled by the angle of incidence .beta.1 (FIG. 1) of ray 70 at the source end of the ray. In this instance, .beta.1=.theta..sub.1 =.theta..sub.R since velocity is constant. It is noted that .beta.1 does not satisfy this equality in the case where the velocity is not constant along ray 70. However, .beta.1 continues to control the slope of the event in gather 40. For a common source gather (not shown), the slope of event 74, assuming constant velocity, is equal to the slope of the event in common receiver gather 40. In the case of non-constant velocity along ray 70, however, the angle of incidence .beta.2 at the receiver controls the slope of event 74 in a common source gather. Thus, the criteria is established that, for constant velocity media, p--p primary events can be identified as having the same slope in a source gather as in a corresponding receiver gather.
It is to be understood that the prior art techniques described above are intended as being exemplary of more notable prior art approaches to the problem of identifying specific seismic data types and that these approaches are not intended to encompass all of the various techniques which have been applied to the problem. As an additional note, it should be mentioned that all of the foregoing techniques are typically automated in a high speed data processing environment simply due to the relatively enormous amount of data which is present in a typical seismic data record. These techniques have been graphically illustrated only for purposes of enhancing the reader's understanding.
Having described a number of approaches to the problem of identifying/separating seismic data from the overall seismic data record, it should be appreciated that these approaches and associated techniques have proven to be of some value. However, it is submitted that these prior art techniques, as well as other techniques which have not been described for purposes of brevity, share two weaknesses. First, these techniques have a tendency to reject data which is valid and, second, they share a tendency to fail to exclude data from a selected type which, in fact, should be excluded. Either of these weaknesses, even if present to a quite limited extent, can significantly and adversely affect the end result which is obtained in the application of the data, for example, in generating a reflection image. Thus, there continues to be a need for still more effective techniques for the identification/separation of specific types of data from the overall seismic data record in order to enhance seismic imaging and related applications.
The present invention provides a highly effective, heretofore unseen approach for resolving the problems encountered in the prior art in the identification of specific types of data contained by the seismic data record or similar such data sets.